In common methods for producing oil from a well drilled into an oil-bearing subsurface formation, a string of steel production tubing is positioned in the well bore and extending from the subsurface production zone up to a pump jack in accordance with well-known methods, and as schematically illustrated in FIG. 1 herein. A downhole pump is disposed within the production tubing in the production zone to raise well fluids (e.g., oil, gas, formation water) to the surface, by reciprocating vertical movement of a travelling valve incorporated into the pump. The travelling valve is reciprocated by a typically steel “sucker rod” extending upward within the production tubing to the well where it connects to a polished rod (alternatively referred to as a “polish rod”) extending upward through a wellhead tee and stuffing box to connect to the “horse head” at the free end of the “walking beam” of the pump jack. By means of a suitable motor and associated mechanical linkage, the pump jack is operable to rock the walking beam such that the horse head reciprocates up and down, thereby alternately raising and lowering the sucker rod and the travelling valve, causing well fluids to be drawn into the well and the production tubing, and to be moved upward within the production tubing toward the wellhead, on each upward stroke of the travelling valve.
As the sucker rod reciprocates up and down within the production tubing, it inevitably comes into contact with the inner wall of the tubing. The resultant friction between the steel sucker rod and the tubing causes wear on both the rod and the tubing. In addition, this friction increases the magnitude of the force that needs to be provided by the pump jack to raise the sucker rod (and the travelling valve) on each upward stroke.
As an alternative to a pump jack as described above, well fluids may also be produced using a wellhead apparatus that rotates the sucker rod to drive a downhole screw pump (also known as a positive displacement pump), rather than reciprocating the sucker rod up and down. Although rotating sucker rods thus function in a different fashion than reciprocating sucker rods, they are nonetheless prone to friction-induced wear due to contact with the tubing.
Sucker rods are typically round or semi-elliptical in cross-section, and typically hot-rolled from carbon or alloy steel, with diameters ranging from ⅝ to 1⅛ inches. Sucker rods are commonly made up as a string of individual rods (typically 25 to 30 feet in length) threaded together using internally-threaded tubular couplers. The ends of a threaded sucker rod are typically upset (i.e., larger in diameter than the main length of the rod), and are threaded for mating engagement with couplers. The upset portion at each end of a threaded sucker rod is typically about 5 inches long, and includes a tool-engagement section to facilitate use of a wrench to tighten a coupler onto the rod. However, it is also known to use continuous sucker rod, such as COROD® continuous sucker rod available from Weatherford International Ltd.
It is known to mitigate the undesirable consequences of friction between sucker rods and production tubing by lining the tubing (i.e., coating the inner surfaces of the tubing) with a low-friction material such as HDPE (high-density polyethylene). Although lined tubing reduces friction, the steel sucker rods are still prone to deterioration due to friction-induced wear notwithstanding the lining, and friction loads still will be imposed on the pump jack. For these reasons, there is a need in the oil and gas industry for means for further reducing friction between sucker rods and the production tubing in which they reciprocate.